This background and documents mentioned below are provided for the purpose of making known information believed by the applicant to be of possible relevance to the present invention, and in particular allowing the reader to understand advantages of the invention over devices and methods known to the inventor, but not necessarily public. No admission is necessarily intended, nor should be construed as admitting, that any of the following documents or methods known to the inventor constitute legally citable prior art against the present invention.
After an oil or gas well is drilled within an underground hydrocarbon formation, the zones of interest need to be completed, namely conditioned typically by a fracking operation, in order to most quickly and to the greatest extent possible produce oil and/or gas from each particular zone. If the zone of interest requires a type of fracture stimulation, including but not limited to acid fracture or propped fracture, the zone of interest will be isolated to focus the fracture on the particular zone, and to prevent fracture in other zones which may not be desired.
Liner systems can be used prior to conducting the fracture stimulation and can be run in either open hole or cased hole applications.
In the stimulation of directional and horizontal wells, it can be desirable to treat multiple stages in a single zone, known as a cluster, with a single fracture stimulation. It can also be desirable to treat more than one zone with a single fracture stimulation to save time and expense associated with multiple treatments and time spent running tubing and tools in and out of the wellbore.
Various downhole tools and systems have been used to stimulate wells by permitting treatment/fracturing in multiple contiguous regions within a single zone. Many of such tools and systems require components within the bore of the liner at each valve which disadvantageously restricts flow of fluid through the liner during fracture pumping operations, and also, to the extent such systems or remnants thereof remain, similarly restrict production of hydrocarbons. Due to such flow restrictions, pressure drops occur, which result in less efficient operations as there is pressure loss incurred prior to the fracture fluid contacting the zone. Ideally, less pressure drop is desired to conduct a fracture stimulation more efficiently in each stage and in addition. In addition, such tools and methods require milling out of such components at each valve location prior to switching to production flow from the hydrocarbon bearing zones. It is desirous to have fewer materials/components to mill out within the bore liner immediately prior to commencing production from the hydrocarbon bearing zones.
Numerous patents and pending patent applications exist related to apparatus and systems for opening a plurality of ports in a liner within a wellbore at multiple contiguous locations therealong, to thereby permit injection of a fluid from such liner into a hydrocarbon formation, typically for the purpose of fracturing the formation at such locations.
For example, U.S. Pat. No. 8,215,411 teaches a plurality of opening sleeve/cluster valves along a liner for wellbore treatment, and utilizes a ball member or plug to open a sleeve at each valve thereby allowing fluid communication between the bore and a port in the sleeve's housing. This invention requires, however, a ball seat corresponding to each sleeve in a cluster valve, potentially restricting flow. The presence of a ball seat at each valve to be opened, due to the resulting bore restriction at each valve sleeve, creates a significant pressure drop across the cluster valve assembly.
U.S. Pat. No. 8,395,879 teaches a hydrostatically powered sliding sleeve. Again, such configuration utilizes a single ball, but each sliding sleeve configuration requires its own ball seat.
U.S. Pat. No. 4,893,678 discloses a multiple-set downhole tool and method that utilizes a single ball. Again, each valve requires a seat which is integral with a sliding sleeve, and which remains with each valve/port. When the sleeve/seat is forced by the ball to slide and thereby open the port, collet fingers may then move radially outwardly, disengaging the ball and allowing the ball to further travel downhole to actuate (open) further ports.
US Patent Application Publication No. 2014/0102709 discloses a tool and method for fracturing a wellbore that uses a single ball, each valve with a deformable ball seat. Again, each valve has a valve seat which remains with each valve/port.
Other patents and published applications avoid the problem of each valve/port having a ball seat which remains with each valve, and provide a dart or ball member which actuates a number of valves/ports. However, such designs are not without their own unique drawbacks.
For example, US 2013/0068484 published Mar. 21, 2013, inter alia in FIG. 6 thereof, (and likewise to same effect US 2004/0118564 published Jun. 24, 2004, likewise in FIG. 6 thereof) teaches an axially movable sliding sleeve 322 which is capable of actuating (i.e. opening) a number of downhole port sleeves 325a, 325b to thereby open corresponding respective downhole ports 317a, 317a′ which are normally covered by port sleeve 325a, and similarly subsequently open respective downhole ports 317b, 317b′ normally covered by port sleeve 325b. Sliding sleeve 322 is mounted by a shear pin 350 in the tubing string. Plug/ball 324 is inserted in the tubing, and uphole fluid pressure applied thereto cause plug 324 to travel downwardly in the in the string and abut sliding sleeve 322, further causing shear pin 350 to shear and thus sleeve 322 to then be driven downhole. Spring-biased dogs 351 on outer periphery of sliding sleeve 322 then engage inner profile 353a on sliding sleeve 325a and cause sleeve 325a (due to fluid pressure acting on plug 324) to move downhole thereby opening ports 317a, 317a′. As noted in paragraph [0071] therein, continued application of fluid pressure causes dogs 351 to collapse, thereby releasing sleeve 322 from engagement with inner profile 353a on sliding sleeve 325, and allowing sleeve 322 to further travel downhole and actuate (i.e. open) further sleeves in like manner. Although not expressly mentioned nor shown in US 2013/0068484, seals are necessary around dogs 351 in order to allow creation of a pressure differential when such continued application of fluid pressure is applied, in order to cause collapse of such dogs to allow disengagement with a first sleeve and allow the dart to thereafter further travel downhole for subsequent actuation of additional downhole sleeves and ports. The necessity for seals around dogs 351 necessarily introduces added mechanical complexity and the possibility of inability to release sleeve 322 from engagement if such seals were to leak due to the then-inability to create a pressure differential.
WO 2013/048810 entitled “Multizone Treatment System” published Apr. 4, 2013 teaches a system and method for successively opening flow control devises (which may be sliding sleeves) in a tubing string along a length thereof, commencing with a most downhole valve and opening a sleeve at such location, and by insertion of additional darts progressing successively upwardly in the tubing string to open further uphole sleeves. The tubing string is provided with a plurality of spaced apart flow control devices, such as sliding sleeves, each having an annulary-located recess therein with a unique profile relative to other flow control devices. A first dart, having an engagement feature sized to correspond with a selected annulary-located recess of a particular most-downhole flow control device, is injected, and such dart passes to actuate the flow control device to allow it to open a port. The process is progressively repeated for additional uphole flow control devices by injecting additional darts, having corresponding features to engage a selected flow control device. The darts are then drilled out to allow production from the tubing. Disadvantageously, only one dart can open one port, and thus a plurality of contiguously spaced ports are not capable of being opened by a single dart using such apparatus/method, thereby rendering such system/method time consuming.
CA 2,842,568 entitled “Apparatus and Method for Perforating a Wellbore Casing, and Method and Apparatus for Fracturing a Formation” published May 29, 2014 teaches inter alia dart members similar to the dart of WO 2013/048810, each dart having a protruding spring-biased profile uniquely sized to engage a similarly-sized annular recess on a plurality of downhole sliding sleeves, and thereby open sliding sleeve, with further means being provided on each of such sliding sleeves to allow the single dart member to further travel downhole and open additional sleeves having similar-sized annular recesses. No collet sleeve is provided, and a non-beveled (non-chamfered) surface on the annular recess of the most downhole sleeve is used to retain the dart from travelling further downhole. Disadvantageously, in comparison to the system as hereinafter described, the configuration of the dart, namely having a spring-biased profile and a cup seal thereon, essentially requires the dart to be virtually solid and thereby permanent obstruction to the wellbore once opening the last of a series of slidable sleeves. If additional uphole sleeves are desired to be actuated using a second dart (having a narrower protruding spring-biased profile than the first dart used), the first dart must be installed using a locator tool and thereafter retrieved, after actuating a plurality of sleeves and associated ports using such tool, as shown in FIGS. 9A-9D. Such a system involves use of extensive equipment from surface and the need of a bypass port that need by opened and closed to allow effective operation including insertion and withdrawal of the locator tool. These steps and features complicate the operation of such prior art system and add to expense and time.
A need exists for an effective and simpler system which does away with tools from surface for opening production tubing for use after actuation of such ports.